Active development. Solar plus storage under a new mandate, ancillary services, and island power.
On 26 February 2026 the Department of Energy issued Department Circular DC2026-02-0008, a supplemental and amendatory framework to the 2023 energy storage policy. It requires all prospective variable renewable energy facilities of 10 MW and above to integrate storage of at least 20 percent of the plant's capacity.7 The same update recognises storage with virtual inertia and fast response in supporting frequency stability, and directs the transmission network provider and distribution utilities to build storage into grid reinforcement planning and the Transmission Development Plan.8
For a developer this converts storage from an optional revenue enhancement into a sizing constraint applied to every new project above the threshold. The design question becomes how to make a mandated 20 percent do useful commercial work rather than whether to include storage at all.
Procurement has followed. The fourth Green Energy Auction was the first to admit Integrated Renewable Energy and Energy Storage Systems, and awarded contracts covering 1.19 GW of such bids.9 The House of Representatives has passed a national energy storage framework bill that would make the Department of Energy the lead implementing agency and require the regulator to build a framework for licensing, pricing and cost recovery.9 The regulator has also temporarily suspended power delivery service charges on storage systems, describing it as a time bound measure to remove a disincentive.10 A 2026 edition of the grid code is in progress, adding technical requirements for solar plus storage plants and standalone storage using grid forming inverters, alongside new cybersecurity, reserve and reliability rules.11
Regionally targeted procurement is running in parallel, including a requirement for at least 170 MW of storage across Cebu, Negros and Panay to absorb rising solar and wind output, with seventeen storage applications under review across the Visayas and Mindanao.12
Behind the meter, by contrast, is very small. One published estimate puts Philippine behind the meter storage at around 24 MW in 2025.10 We treat behind the meter here as an early market with real cases at specific sites rather than a segment with an established playbook.
The Microgrid Systems Act, Republic Act 11646, sets the route for island and off grid projects. A microgrid system provider is not treated as a public utility operator and does not need a franchise from Congress, but it does need an authority to operate from the regulator.13 Providers may serve areas identified by a distribution utility, or declared by the Department of Energy, following a competitive selection process, and the implementing rules allow a Swiss challenge route for unsolicited proposals.14 Distribution utilities must file a ten year local total electrification roadmap with an inventory of unserved and underserved areas, and end users may petition to have an area declared if it has been left out.14 Revised implementing rules were issued in 2025.15
Unserved means no electricity access. Underserved means supply for less than 24 hours a day.13 The distinction decides which procedural route applies, and it is worth settling before any technical work starts.
Our own work in Mindoro sits under a different arrangement again, the small island and isolated grid system operator framework administered by the transmission corporation. That framework, rather than the on grid ancillary service market, sets what a storage asset can earn there, and the modelling had to be built around it.
The core problem was the absence of a price. There is no precedent storage dispatchable reserve contract in the Philippines to point at, so a market price for the service does not exist. We took the regulator approved ancillary service procurement rates from the grid operator's published 2025 to 2034 procurement plan and used those as the modelling baseline, extracted by service type and by grid region. Regulating reserve rates came out materially above contingency reserve rates, roughly 2.08 to 2.20 pesos per kilowatt hour against 1.25 to 1.50, which changes which service a battery should be optimised for. Off grid systems under the small island framework also tend to command a premium over on grid benchmarks, which matters for a Mindoro business case.
The second problem was document trust. Contract and rate documents in this chain pass through several authenticating bodies before they can be relied on, and the storage specific terminology does not always survive translation cleanly. Getting the baseline numbers to a state a financial model could stand on took as much work as the modelling itself.
The lesson we carried out of it is the one now stated on every off grid model we produce. When there is no comparable transaction, the baseline is a regulatory document, not a market price, and the model has to say so on its front page rather than bury the assumption in an appendix.